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CO2 removal optimisation for the BR-E membrane system by data analysis and modelling

PETROLEUM EXPLORATION & PRODUCTION

PETROVIETNAM JOURNAL
Volume 10/2019, p. 4 - 13
ISSN-0866-854X

CO2 removal optimisation for the BR-E membrane system
by data analysis and modelling
Nguyen Hai An
Petrovietnam Exploration and Production Corporation
Email: annh1@pvep.com.vn

Summary
Development of offshore high carbon dioxide (CO2) gas fields will indisputably pose significant new challenges for all E&P companies
in the world. Acid gas removal from natural gas is an indispensable treatment process that is required to boost the produced gas quality
prior to its utilisation. The use of membrane units has increased in natural gas treatment plants, particularly for acid gas removal.
Such technology shows tremendous advantages over other conventional methods in terms of removal efficiency, compactness, and
environmental friendliness.
BR-E CO2 removal facility using membrane technology has been utilised for more than 10 years. As new acid gas fields require
increasingly high gas volumes (more than 700 MMscfd production) and have very high CO2 content (above 50%), existing membrane
performance is no longer economical for such new field development.

In this paper, a data analysis model for membrane separation has been incorporated with HYSYS as a user defined unit operation in
order to optimise performance and redesign the membrane system for CO2 separation from natural gas. Parameter sensitivities have been
studied for different crude gas flow and CO2 contained in gas.
Key words: Petroleum system modelling, a prospect, drainage area, hydrocarbon migration and accumulation, Block 09-3/12.

1. Introduction
Membrane systems are modular and can easily cope
with the increase of feed flow rate. An increase in feed
flow rate requires a proportional increase in membrane
area requirements. If the membrane area is fixed, an
increase in feed flow will result in an increase of CO2 in the
produced gas.
Next to the changes in feed-gas conditions (flow and
composition), normal membrane aging can result in a CO2
concentration increase in the sales gas. Membranes are
subjected to a lifetime that varies with feed-gas conditions,
membrane pre-treatment design, and operator skills. The
BR-E gas plant has shown excellent performance with the
membrane lifetime of more than 10 years.
The design of a membrane system takes into account
the natural performance decline (membrane aging) by
sizing the system for end-of-life conditions so that the
Date of receipt: 5/11/2019. Date of review and editing: 5 - 11/11/2019.
Date of approval: 11/11/2019.

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PETROVIETNAM - JOURNAL VOL 10/2019

system will always reach the required specifications.
During the lifetime of the membrane, the system will
require minor operational adjustments as the membrane
properties (selectivity and permeability) vary.
The research will further describe how the BR-E gas
plant has been optimised as feed-gas conditions changed
and as membranes aged, the objectives of producing
gas with acceptable CO2 content while minimising
hydrocarbon losses that transpose directly in sales gas
volume and revenue.
2. Removal of CO2 with membranes


2.1 Membrane general
The most common membranes for gas sweetening
processes are cellulose acetate (CA) membranes [1].
Recently, fixed site carrier membranes showed a great
potential for removal of CO2. A simple membrane process
can be schematically represented as shown in Figure 1.
Membrane based gas separation process depends on
the gas components, membrane material and the process


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conditions. The governing flux equation (Equation 1) is given by
Fick’s law of diffusion where the driving force is the partial pressure
difference over the membrane.
,

=

,

=

=

(



)

(1)

Where J (m3(STP)/m2 h) is the flux of gas component i, qp is the
volume of the permeating gas (i) (m3(STP)/h), Pi is the permeability of
gas component i ((m3(STP)/m2 h bar), ph and pl are feed and permeate
side pressures (bar), xi and yi are the fractions of component i on the
feed and permeate sides and Am (m2) is the membrane area required
for the permeation. The permeability (P) can be expressed as
(2)

P = DAB × S

Where DAB (m2/s) is the diffusivity and S (m3(STP)/m3 bar) is the
solubility coefficient for the gas in the membrane. The ratio of pure
gas permeabilities (PA, PB) gives the separation factor or membrane
selectivity, α = PA/PB.
Permeate
G yi

Membrane

F xi
Feed

R ri
Retentate

Figure 1. Schematic illustration of membrane separation process.

It is important to mention here that
Equation 1 can be used to accurately and
predictably rationalise the properties of gas
permeation membranes.
2.2. Membrane modules
In order to make a membrane module
for industrial application [2, 3] that consists
of cellulose acetate membrane sheets that
are bound onto a woven cloth support. A
membrane sheet has two layers: a relatively
thick microporous layer that is in contact with
the cloth support and a thin active layer on top
of the microporous layer.
A membrane element is a spiral wound
assembly with a perforated permeate tube at
its centre (Figure 2). One or more membrane
leaves are wrapped around the permeate
tube. Each leaf contains two membrane-cloth
composite layers that are separated by a rigid,
porous, fluid-conductive permeate channel
spacer. These leaves are separated from each
other by a high-pressure channel spacer. The
membrane leaves are sealed with an adhesive
on three sides; the fourth side is open to the
permeate tube.
As the feed gas passes through the
membrane tubes, the gas is separated into a

*Two membrane sheets with permeate spacer between: leaves are separated by feed spacers and
wrapped around a permeate tube facing it with three open ends.

Figure 2. Spiral-wound membrane elements [3].
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PETROLEUM EXPLORATION & PRODUCTION

high-pressure methane rich gas (residual), and a lowpressure gas stream concentrated in carbon dioxide
(permeate).
The first membrane stage is designed to produce
a residual gas (sales gas) with low CO2 concentration,
which is supplied to the export compressors for
gas metering. The permeate gas containing high
CO2 %mol is compressed through the permeate
compressor and then directed to the second stage
membrane package.
The second membrane stage is designed to
recover most of the hydrocarbons from the first-stage
permeate gas. The second membrane stage residual
gas is recycled back to the first membrane stage.
The second stage permeate gas containing the high
concentration of CO2 is flared.
2.3. Membrane system configurations
A single-stage membrane configuration consists
of one permeation unit or more than one unit, but all
are arranged in a barrel setup and have the same feed
composition.
This configuration is the simplest and corresponds
to the lowest capital investment. The single-stage
configuration is schematically shown in Figure 3.
The crude natural gas flows over the feed side of the
membrane. Along the way, CO2 permeates through
the membrane to the permeate side. The retentate
leaves the membrane with nearly the same pressure
as the feed. On the permeate side, a permeate stream
enriched with CO2 leaves the membrane.
As seen in many industrial applications [3], the
single-stage membrane separation has limitation in
achieving high quality permeate or retentate while
typically the objective of separation is either of
these. As such, more stages are required in order to
accomplish the desired product quality and recovery
ratio. Figure 4 illustrates a simplified flow scheme of
a two-stage cascade membrane system. A multistage
configuration reduces the hydrocarbon losses to
a minimum, however, those plants have higher
investment costs than single stage configurations.
The permeate stream of the first membrane serves
as feed for the second membrane. Therefore, the
permeate stream needs to be recompressed and
cooled. The retentate stream of the second membrane
stage is recompressed, cooled and recycled as feed
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PETROVIETNAM - JOURNAL VOL 10/2019

to the first stage. The retentate stream from the first stage is
collected as the product gas.
3. BR-E CO2 removal facility
The BR-E CO2 removal facility is 370km from Ca Mau
terminal. The platform processes gas condensate from northern
fields complex, and associated gas from the southern oil fields.
The project produces about 350MMscfd (max) of export gas
at an export pressure of 101 bars and 3,700stb of stabilised
condensate. The BR-E platform has been in operation since in
Q1, 2007 with the main function to process high CO2 production
gas to meet the sale gas specification of 8% mol CO2
The flow diagram of the BR-E gas facility (Figure 5) shows
gas flowing from the complexes into the system. First it enters
a two-phase feed gas separator where the main condensategas separation takes place. Gas from the separator goes to
the Coalescing Unit for liquid and mist elimination to reduce
overall plant pressure drop. Then it flows to the Membranes
System, which consists of a temperature swing adsorption
(TSA) regenerable beds for the simultaneous removal of
aromatics, water and other contaminants (e.g., mercury).
The retentate stream of the second membrane stage is
recycled as feed to the first stage. This combined stream has a
design CO2 content of 40 - 45% mol and is the feed gas to the
first-stage membrane skids. The retentate stream from the first
stage is collected as product gas. Condensate collected from
the various processing steps moves to stabilisation before
Residue
(CO2 Reduced)
Feed

Membrane
Unit
Permeate
(CO2 Enriched)

Figure 3. Single-stage flow scheme

Residue

Feed
Permeate

Figure 4. Dual-stage flow scheme.


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Export Gas
to BRA

Coalescer filter A/B

Regeneration
Gas System

Feed gas
Separator

Gas from
Northern
fields
Gas from
Southern
fields

MEMGUARD Adsorber A - F

Particle Filter A/B
Lean CO2 Gas Retrigeration Sys
Separator

CW

Membrane
Pre-hearers

Residue Gas @
Sales Gas
Specifications
CO2 to Vent

CO2 to Vent

Stabilised
Condensate
BRA

Condensate
Stabilisation
System

Primary
Membrane A - F

Retrigeration Sys

Secondary
Membrane A - B

Produced
water
Overboard

2 Stage Permeate Compressor A/B/C

700

46

600

44
42

500

40
400
38
300
36
200

CO2 content (%)

Gas flowrate (MMscfd)

Figure 5. Flow diagram for CO2 removal on BR-E platform [4].

34

100

32
Feed Flowrate

Process

% CO2
30

201X

Dec

Nov

Oct

Sep

Aug

Jul

Jun

May

Apr

Mar

Feb

Jan

Dec

Nov

Oct

Sep

Aug

Jul

Jun

May

Apr

Mar

Feb

Jan

0

201Y

Figure 6. Gas process behaviour.

being stored in the three storage tanks. The stabiliser
tower removes the light hydrocarbons to avoid release in
the tanks and to achieve the rvp specification.
After heating to required temperature, the gas enters
the gas-sweetening system (dual-stage membrane
package) to reduce CO2 in the export gas. The final step is
to export the gas via the export compressors.

3.1. Operation performance
Throughout the operating period of two years,
changes were daily made in the feed gas rate and the
CO2 concentration. Figure 6 gives information about the
behavior of feed gas flowrate, retentate (“process gas”),
for two different levels of CO2 concentration in the feed
gas. In fact, the CO2 concentration in the retentate product
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PETROLEUM EXPLORATION & PRODUCTION

0.7

0.65

0.6

Stage cut

0.55

0.5
CO2 > 40%
0.45

CO2 < 40%

0.4

0.35

0.3

30

80

130

180

230

280

330

380

430

Feed gas rate (MMscfd)

Figure 7. Total gas stage cut for BR-E membranes system.

remained below the pipeline specification throughout the
measurement. These results show that, even with a CO2
concentration of over 40% mol in the feed, it was possible
to meet the pipeline specification of 8% mol CO2.
Figure 7 shows the “total gas stage cut” for different
CO2 components of natural gas as a function of feed gas
rate for membranes. The “stage cut” is generally defined
as the fraction of the feed stream allowed to permeate
through the membrane, i.e. the permeate/feed ratio. In
the measurement period, it was found necessary to “force”
the CO2 balances for some surveys to obtain a good data
fit, especially the data for high CO2 concentrations in the
feed. The field staff observed that the CO2 concentration in
the “sour” gas from the well typically varied by about 5%
mol out of an average concentration of about 40% mol.
This meant that the CO2 stage cut for feed gases with high
CO2 content could vary by as much as 10%. For consistency,
the CH4 balances were also forced as necessary, but there
was much less variability in these data because of the
relatively high concentration of CH4 in all streams.

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PETROVIETNAM - JOURNAL VOL 10/2019

The parameters of feed flow rate and CO2 concentration
in the feed are arbitrarily grouped in Figure 8 into ranges
denoted as “CO2 < 40%” and “CO2 > 40%”. As can be seen
from this figure, the data are generally consistent in
that the stage cuts decrease with increasing feed flow
rate. The scatter in the data is not unusual for field test
conditions. It was not possible to obtain data at higher
feed flow rates with medium-to-high CO2 concentrations
in the feed without exceeding the pipeline-specified limit
of 8% mol CO2 in the retentate. Therefore, the data are
generally limited to lower feed flow rates and lower CO2
concentrations. There was no indication of membrane
deterioration with time, based on the field test data.
In general, the stage cuts for the membrane system
followed the same general dependence on feed flow rate
and CO2 concentration in the feed. High CO2 stage cuts
were necessary to reduce the CO2 concentration in the
retentate product to the pipeline specification of 8% mol,
however the outlet gas rate was decreased accordingly.
While this results in a better CO2 removal, it also increases
the losses of CH4 and higher hydrocarbons in the permeate


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3.2. Process simulation

0.7
0.7
0.65
0.65
0.6
0.6
0.55
0.55
0.5
0.5
0.45
0.45
0.4
0.4
0.35
0.35
0.3
0.3 30
30

32
32

34
34

36
36

38
40
42
44
38
40
42
44
CO2 concentrationof feed gas (%)
CO2 concentrationof feed gas (%)

46
46

48
48

50
50

0.7
0.7
0.65
0.65

Stage
cut
Stage
cut

0.6
0.6
0.55
0.55
0.5
0.5
0.45
0.45
0.4
0.4
0.35
0.35
0.3
0.3 30
30

80
80

130
130

180
230
280
180 Outlet 230
280
gas (MMscfd)
Outlet gas (MMscfd)

330
330

380
380

430
430

Figure 8. Depends of outlet gas on CO2 concentration of feed gas.

(vent) stream. The component stage cuts also increase, as expected, with increasing
pressure, because the partial pressures of the components increase.
It should be pointed out that the actual field surveyed flow rates were
generally much lower than the design rate since the purpose of the tests was to
obtain operating data over a wide range of conditions. Therefore, back-diffusion
and perfect mixing were possible, and the methane loss in the permeate was
generally higher than desired in commercial operation.

The numerous material
balances that need to be
resolved simultaneously within
a multistage membrane unit
make the prediction of unit’s
performance using conventional
mathematical
solvers
(e.g.
spreadsheet)
challenging.
Further, the struggle to solve the
indicated balances obstructs any
intended process optimisation.
Hence, the development of
a flexible, efficient, and userfriendly model is crucial to
simulate, evaluate and optimise
such processes.
The membrane separation
process is modelled based
on
the
solution-diffusion
mechanism, which is governed
by the following mass transfer
equation. Detailed modelling of
the CO2 removal BR-E facility was
performed with the confirmation
of the capability of this equipment
to process the design cases.
Stream data for the boundaries
of the model were provided,
for the high and low CO2 cases.
The new process configuration
and updated production data
were incorporated into the
HYSYS model, which has been
further amended to align with
the two design cases for CO2
concentration.
In order to align with the
models of design cases, it was
necessary to match streams at
the interface with the boundary
stream data provided. As these
design cases represent different
production rates for modelling,
it was necessary to adjust flows
from wellhead platforms to the
processing facilities.

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PETROLEUM EXPLORATION & PRODUCTION

The HYSYS models were
consolidated and amended to
match the facility processing
configuration
following
the
upcoming
shutdown.
The
consolidation
process
was
performed
at
the
request
incorporating the production
data into a whole field model.
This was achieved through the
substitution of the fields models
with streams specified to match
forecast production rates. Other
amendments included both recent
changes to facilities and the work
planned for the shutdown.

Permeat concentration (y)CO2

Expriment
Model

0.9

0.8

0.7

0.6
0.4

0.5

Stage cut (τ)

0.6

0,7

Figure 9. Model validation against experimental data.
0.6
60
0.5
0.4

40

0.3

30

0.2

20

0.1

10

0
10000

11000

12000

13000

14000

0
15000

Compressor Power (hp)

Figure 10. Power requirement analysis.
Table 1. Factors for model
Description
Feed gas
Flow rate
Pressure
Temperature
CO2 concentration
Outlet gas
Flow rate
Pressure (expected)
Temperature (max)
CO2 concentration
Vent (CO2 rich) gas
Flow rate
Pressure (min)
Allowable skid dP
Hydrocarbon recovery

10

Unit

Actual

High CO2

Low CO2

MMscfd
kPag
C deg
% mol

650
4000
30
38 - 44

750
4000
30
50

630
4000
30
35

MMscfd
kPag
C deg
% mol

400
3200
35
7.8 - 8

360
3000
35
8

450
3000
35
8

MMscfd
kPag
kPa
%

350
250
800
87 - 92

350
250
800
90 - 95

210
250
800
93 - 98

PETROVIETNAM - JOURNAL VOL 10/2019

Membrane selectivity

50
CO2 content in feed

To investigate the accuracy
of the mathematical model and
the proposed solution algorithm,
simulation
predictions
were
validated against observed data
reported by operator in two
years. The feed enters the skid
at a pressure of 4000kPag, while
the permeate stream is collected
from the fibre side at a pressure
of 210kPa. These experimental
conditions were used to investigate
the membrane performance at
high feed composition, pressure
ratio, and target component
selectivity. The model results are

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plotted against the experimental results in Figure 9 showing good agreement
with experimental data over the tested range of stage cut.
4. Results and discussion
The research will determine the ability of the existing facilities to meet
the new required capacities for between 35% and 50% CO2 in the feed,

0.6
60
0.5
0.4

40

0.3

30

0.2

20

0.1

10

0
0

50

100
Total Memberane area

Membrane selectivity

CO2 content in feed

50

0
200

150

Figure 11. Total membranes requirement analysis.

identify bottlenecks and estimate work
required to increase gas export volume.
Hence, the maximum potential flow rate
through the CO2 removal equipment on
BR-E has been analysed by considering
two operating cases: high CO2 case (a
feed gas of 50% CO2), and low CO2 case
(a feed gas of 35% CO2).
To relieve some bottlenecks and
produce maximum capacities, some
processing
reconfigurations
and
additional equipment have been
studied. These design cases only
consider the CO2 removal equipment
without considering the ability of the
remainder of the processing facilities
to either supply sufficient feed gas or
export the subsequent sales gas.
The composition, flow rates,
pressures and temperature of crude
natural gas depend mainly on the

450

Membranes Opti

Processed gas gross (MMscfd)

400

Pipeline Capacity

Performance Opti
350

Base design

35% Feed CO2

300

40% Feed CO2
44.5% Feed CO2
50% Feed CO2

250

Base
Performance Optimisation
Membrane Optimisation

200
500

600

700

800

Feed gas rate (MMscfd)

Figure 12. Impact of performance optimisation and membranes enhancement.

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PETROLEUM EXPLORATION & PRODUCTION

source therefore feed conditions that are typical for
offshore natural gas treatment skid are selected. As a
result, the mentioned factors of the feed, as well as the
export gas, are given in Table 1.
On the other hand, a wide range of feed pressures
(10 - 100 bar) and membrane selectivity (5 - 80) has been
investigated. The outlet residue CO2 concentration is set
to 8% while the outlet permeate pressure for each stage
is not greater than 32 bar. The thickness of membrane is
considered to be 1000A˚ (3.937 × 10-6 in.). In addition, it
is assumed that maximum outlet temperatures in the
compressors are limited to 35oC giving the compression
ratio of 20 over each compressor stage. The temperature
of feed stream is decreased to 25oC before introducing
into the membrane using cooler.
4.1. Compressor power
The effect of feed composition, feed pressure
and membrane selectivity on the compressor power
requirement has been investigated for the proposed
design configurations. The compressor power is given by
the expression
Figure 6 shows that the compressor power
requirement increases with the increase in CO2
composition of the feed until it reaches its maximum
point. A further increase can lead to the decrease in
the compressor power requirement. The reason for this
behaviour is the characteristics of chosen selectivity of
the membrane. The effect of membrane selectivity on
the compressor power requirement for different design
configurations has also been studied as shown in Figure
8. It shows that there is a sudden increase in power
requirement by increasing membrane selectivity between
5 and 20, but if we keep increasing the selectivity, there is
a slight decrease in compressor power requirement. It is
due to the characteristics of specific feed and operating
conditions for the investigation.
4.2. Total membrane area
The CO2 rich crudes demand a larger separation area
to achieve the targeted gas quality, which in turn increases
the likelihood of methane slip, and subsequently amplifies
the gas treatment cost. Besides, due to the significant and
irrecoverable methane losses, that contribute most to the
total treatment cost, the adoption of the parallel singlestage design is not recommended.
The effect of feed composition on the total membrane
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area required for the effective separation is studied for
proposed design configurations as shown in Figure 11. It
is observed that the total membrane area increases with
the increase in CO2 composition of the feed until it reaches
its maximum point. After that, a further increase can lead
to the decrease in the membrane area requirement. It
is due to the characteristics of chosen selectivity of the
membrane. It can also be observed that recycling the
retentate stream in the multiple stage configurations
can lead to large requirements of area, while in the
single stage system, recycling has minimal effect. Figure
11 also shows the effect of membrane selectivity on the
total membrane area for different design configurations.
Increasing selectivity decreases the membrane area
requirements, which is more pronounced in the
multiple stage configurations, followed by single stage
configuration with recycle and single stage configuration
without recycle.
Because the feed CO2 content and feed gas flow
rate were well below design basis values during the
performance measurement, the observed data were
extrapolated to determine the performance optimisation
at expected values. With new wells being added, the feed
CO2 increased to near design value of 44.5% and additional
feed gas quantities were available for processing. The
system parameters where then adjusted to increase the
feed CO2 to optimal value of 44.5%, and increased feed
flow to the rate required to deliver the 400 MMscfd of
sales gas gross (Export pipeline capacity). Adjustments
were made by increasing the operating temperature at
the membranes. While this improves the CO2 removal
performance, it also decreases hydrocarbon recovery.
The final step was modelled with the design amount
of primary and secondary membrane area on-line. This
extrapolation demonstrated that the unit met system
design requirements and will achieve better hydrocarbon
recovery by producing 400MMscfd of sales gas gross with
less than the 750MMscfd feed rate used as the design basis.
5. Conclusions
Large offshore gas processing projects are complex
and expensive to operate. The BR-E CO2 removal facility,
with membrane process system, meets the specific
CO2 concentration requirements of export pipeline.
The system has been operated for more than 10 years
meeting specifications and without significant membrane
replacement.


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Data analysis and mathematic model allow process
engineers to simulate, optimise and evaluate the
performance of complex dual-stage membrane processes.
In this research, HYSYS module was utilised to simulate
and subsequently evaluate the efficiency of the CO2
removal process, where the crude gas CO2 content was
dropped from 35 - 50% mol down to 8% mol. The result
showed that with the right temperature, pressure, and
membranes configuration, the sale gas specification were
met and the operational challenges, such as high feed
flow rate, or bottlenecks were mitigated. Furthermore,
the HYSYS user defined unit operation has the potential
to be applied for complex membrane system design and
optimisation study.

References
1. P.Bernardo, E.Drioli, G.Golemme. Membrane
gas separation: A review/state of the art. Industrial &
Engineering Chemistry Research. 2009; 48 (10): p. 4638 4663.
2. Honeywell Company. UOP separexTM membrane
technology. UOP LLC. 2009.
3. David Dortmundt, Mark Schott and Tom Cnop.
Sour gas processing applications using separex membrane
technology. UOP LLC. 2007.
4. PVEP. BR-E CO2 removal process overview.

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